System and method for synchronizing multiple generators with an electrical power distribution system

ABSTRACT

Systems and method for synchronizing power generators with a power grid are provided. One system among various implementations includes a plurality of synchronization modules, wherein each synchronization module corresponds to one power generator. The synchronization modules are configured to output a control signal to adjust a frequency of the respective power generator to correspond with the frequency of the existing power grid. The system also includes a central controller in communication with the plurality of synchronization modules. The central controller is configured to determine a propagation delay with respect to each synchronization module. The propagation delay is a measure of time for a signal to propagate from the respective synchronization module to the central controller. The central controller is further configured to send a control signal to each synchronization module to control when each synchronization module connects the respective power generator to the existing power grid.

PRIORITY

The present application is a continuation-in-part application of U.S.application Ser. No. 13/013,171, filed Jan. 25, 2011, which is acontinuation application of U.S. application Ser. No. 11/894,553, filedAug. 21, 2007, now U.S. Pat. No. 7,877,169, the contents of which arehereby incorporated by reference in their entirety.

BACKGROUND OF THE INVENTION

1. Field

The present disclosure relates generally to power generation devices.More particularly, the present disclosure relates to a system and methodfor synchronizing power generation devices to ac electrical powersystems.

2. Description of the Related Art

Generally speaking, a power plant uses generators rotated by steam,water, or an engine to produce electrical energy in the form ofthree-phase alternating current of a fixed voltage and a fixedfrequency. Electricity so produced is then delivered to consumersthrough a network of transformers and transmission lines often referredto as a power distribution grid (i.e., the grid). Within the grid of asingle utility company, power generation will often be distributed amongseveral power plants to reduce distribution costs and to improve thereliability of the system. With multiple generators operating, acustomer need not lose electrical power simply because a singlegenerator has been taken off-line.

As is well known in the art, a generator is a dynamoelectric machineemploying the principles of generator action to produce the electricaloutput. A generator is a mechanically massive structure and electricallycomplex, with typical output power ratings up to 1,500 MVA at voltagesup to 26 kilovolts (kV). A generator can only be connected to a commonelectrical bus, or grid, if turning in synchronization with othergenerators already on the grid. Synchronization requires that thegenerators are producing alternating current at the same frequency, andthat the outputs of the generators are in phase with one another. Ifboth conditions are not met, extremely large electrical currents willflow through the generators, potentially tripping circuit breakerswithin the network, or even damaging equipment. If a national grid is inplace, ideally every generator on the grid, across the entire country,should be turning in synchronization. Presently, to synchronize agenerator to a power grid network, expensive dedicated measuring/controlequipment is required.

Typically, the synchronization equipment is part of a distributed systemincluding discrete components coupled to the power grid and thegenerator. This necessitates the use of a high speed communicationsystem for communicating control signals associated with coupling theauxiliary generator to the power grid network once it has beendetermined that the auxiliary generator has been synchronized. However,such high speed communication systems are prone to many potentialfailures.

Thus, a need exists for techniques for synchronizing an auxiliarygenerator to an electrical system, such as an electrical distributionsystem, e.g., a utility grid in a cost effective manner, without theneed for dedicated measuring/control equipment.

SUMMARY OF THE INVENTION

The present disclosure provides a method and apparatus to control theinterconnection of an auxiliary AC generator with an electrical system,such as an electrical distribution system, e.g., a utility grid.Broadly, a measuring circuit measures the frequency of an auxiliary ACgenerator and the phase angle between one voltage phase of the generatorand the correspondent voltage phase of the electric utility'selectricity supply lines, i.e., the grid, each of which are averaged andfiltered. The measured frequency of the auxiliary AC generator ismatched to the frequency of the electrical system and the measured phaseangle of the generator is matched to the electric utility's electricitysupply lines. Once matching is achieved to within a defined tolerance,interconnecting contactors are closed.

According to one aspect, the step of closing the interconnectingcontactors may be manual or automatic.

According to one aspect, the present disclosure provides a method forcontrolling the interconnection of an auxiliary AC generator with anelectrical system, such as an electrical distribution system, e.g., autility grid, the method comprising: determining the frequency of theauxiliary AC generator; computing the phase angle difference between avoltage phase of the auxiliary generator and a corresponding voltagephase of the multi-phase electrical distribution system; adjusting thefrequency of the auxiliary generator until it is determined to besubstantially equal to the frequency of the electrical distributionsystem and the phase angle is determined to be within a definedtolerance; and closing a set of interconnecting contactors to connectthe auxiliary AC generator to the electrical system.

In accordance with the method, synchronization may be maintained on acontinuous basis as opposed to just during startup.

According to one aspect of the present disclosure, the apparatus tocontrol the interconnection of an auxiliary AC generator with anelectrical system is incorporated into a power meter.

The above and other aspects, features, and advantages of the presentdisclosure will become more apparent in light of the following detaileddescription when taken in conjunction with the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram depicting the general environment in which theinventive system and method are used, according to an embodiment of thepresent disclosure;

FIG. 2 is a diagram depicting the waveform of a single phase ofelectrical power as typically produced by a power plant, according to anembodiment of the present disclosure;

FIG. 3 a is an intelligent electronic device (IED) for monitoring anddetermining an amount of electrical power usage by a consumer;

FIG. 3 b is a block diagram of an apparatus for controlling theinterconnection of an auxiliary generator to an electrical system whichincludes the IED of FIG. 3 a;

FIGS. 4 a & 4 b illustrate a process for controlling the interconnectionof an auxiliary generator to the electrical system, in accordance withan embodiment of the present disclosure;

FIG. 5 is a diagram depicting a synchronization system in accordancewith an embodiment of the present disclosure; and

FIG. 6 is a block diagram depicting the central controller shown in FIG.5, in accordance with an embodiment of the present disclosure.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Preferred embodiments of the present disclosure will be described hereinbelow with reference to the accompanying drawings. In the followingdescription, well-known functions or constructions are not described indetail to avoid obscuring the present disclosure in unnecessary detail.As used herein, intelligent electronic devices (“IED's”) includeProgrammable Logic Controllers (“PLC's”), Remote Terminal Units(“RTU's”), electric power meters, protective relays, fault recorders andother devices which are coupled with power distribution networks tomanage and control the distribution and consumption of electrical power.A meter is a device that records and measures power events, powerquality, current, voltage waveforms, harmonics, transients and otherpower disturbances. Revenue accurate meters (“revenue meter”) relate torevenue accuracy electrical power metering devices with the ability todetect, monitor, report, quantify and communicate power qualityinformation about the power which they are metering. Exemplaryintelligent electronic devices are disclosed and described in thefollowing commonly owned U.S. issued patents and published applications:U.S. patent application Ser. No. 10/146,339 entitled “METER WITH IRDAPORT” filed on May 15, 2002; U.S. patent application Ser. No. 10/958,456entitled “METER HAVING A COMMUNICATION INTERFACE FOR RECEIVING ANDINTERFACING WITH A COMMUNICATION DEVICE” filed on Oct. 5, 2004; U.S.patent application Ser. No. 11/087,438 entitled “SYSTEM AND METHOD FORSIMULTANEOUS COMMUNICATION ON MODBUS AND DNP 3.0 OVER ETHERNET FORELECTRONIC POWER METER” filed on Mar. 23, 2005; U.S. patent applicationSer. No. 11/109,351 entitled ‘SYSTEM AND METHOD FOR COMPENSATING FORPOTENTIAL AND CURRENT TRANSFORMERS IN ENERGY METERS” filed on Apr. 18,2005; U.S. patent application Ser. No. 11/039,316 entitled “MULTIPLEETHERNET PORTS ON POWER METER” filed on Jan. 19, 2005; U.S. patentapplication Ser. No. 11/003,064 entitled “CURRENT INPUTS INTERFACE FORAN ELECTRICAL DEVICE” filed on Dec. 3, 2004; U.S. patent applicationSer. No. 11/042,588 entitled “SYSTEM AND METHOD FOR CONNECTINGELECTRICAL DEVICES USING FIBER OPTIC SERIAL COMMUNICATION” filed on Jan.24, 2005; U.S. Design Pat. No. D525,893 entitled “ELECTRONIC POWERMETER” issued on Aug. 1, 2006; U.S. patent application Ser. No.11/091,254 entitled “SYSTEM AND METHOD FOR PROVIDING UNIVERSALADDITIONAL FUNCTIONALITY FOR POWER METERS” filed on Mar. 28, 2005; U.S.patent application Ser. No. 11/341,802 entitled “METERING DEVICE WITHCONTROL FUNCTIONALITY AND METHOD THEREOF” filed on Jan. 27, 2006; U.S.Design patent application No. 29/224,737 entitled “WALL MOUNT ASSEMBLY”filed on Mar. 7, 2005; U.S. Design Pat. No. D526,920 entitled“ELECTRONIC METER” issued on Aug. 22, 2006; Continuation-in-Part U.S.patent application Ser. No. 11/317,227 entitled “TEST PULSES FORENABLING REVENUE TESTABLE PANEL METERS” filed on Dec. 22, 2005; U.S.Pat. No. 6,735,535 entitled “POWER METER HAVING AN AUTO-CALIBRATIONFEATURE AND DATA ACQUISITION CAPABILITIES” issued on May 11, 2004; U.S.Pat. No. 6,636,030 entitled “REVENUE GRADE METER WITH HIGH-SPEEDTRANSIENT DETECTION” issued on Oct. 21, 2002; U.S. Pat. No. 6,751,563entitled “ELECTRONIC POWER METER” issued on Jun. 15, 2004; U.S. patentapplication Ser. No. 10/896,489 entitled “SYSTEM AND METHOD UTILIZINGVIRTUAL SWITCHING FOR ELECTRIC PANEL METERING” filed on Jul. 22, 2004;U.S. patent application Ser. No. 10/896,521 entitled “ELECTRICAL METERINSTALLATION SYSTEM AND METHOD” filed on Jul. 22, 2004; U.S. patentapplication Ser. No. 10/969,713 entitled “TEST PULSES FOR ENABLINGREVENUE TESTABLE PANEL METERS” filed on Oct. 20, 2004; U.S. patentapplication Ser. No. 10/969,592 entitled “SYSTEM AND METHOD FORPROVIDING COMMUNICATION BETWEEN INTELLIGENT ELECTRONIC DEVICES VIA ANOPEN CHANNEL” filed on Oct. 20, 2004; and U.S. patent application Ser.No. 10/969,706 entitled “ON-LINE WEB ACCESSED ENERGY METER” filed onOct. 20, 2004, the contents of all of which are hereby incorporated byreference in their entireties.

It is to be understood that the present disclosure may be implemented invarious forms of hardware, software, firmware, special purposeprocessors, or a combination thereof. The IED also includes an operatingsystem and micro instruction code. The various processes and functionsdescribed herein may either be part of the micro instruction code orpart of an application program (or a combination thereof) which isexecuted via the operating system.

It is to be further understood that because some of the constituentsystem components and method steps depicted in the accompanying figuresmay be implemented in software, the actual connections between thesystem components (or the process steps) may differ depending upon themanner in which the present disclosure is programmed. Given theteachings of the present disclosure provided herein, one of ordinaryskill in the related art will be able to contemplate these and similarimplementations or configurations of the present disclosure.

Referring now to the drawings, wherein like reference numerals indicatethe same parts throughout the several views, the inventive system isshown in its general environment in FIG. 1. Typically, a grid 200 isformed by a network of transmission lines 220. The grid 200 is used totransmit electrical power from generating facilities, i.e. power plants240 and 260, to customers or end users. For a number of reasons, a grid,whether local, regional, or national, usually includes connections tomultiple power plants. As discussed hereinabove, all power plantsconnected to grid 200 are ideally operating in synchronization and eachpower plant must be synchronized to grid 200 before being placedon-line. Synchronization requires a generator to produces electricity atprecisely the same frequency as the power present on grid 200 andprecisely in phase with grid 200.

Referring next to FIG. 2, typically the electrical power present on agrid, such as grid 20, is in the form of a sine wave 15 of a fixedfrequency, for example, 60 Hz in the United States. As will be apparentto those skilled in the art, sine wave 15 undergoes a zero crossing atzero degrees as shown at points 5 and 13 occurring at times 3 and 11,respectively, and at 180 degrees as shown at points 9 and 19 occurringat times 7 and 17, respectively. To be synchronized with the voltagerepresented by sine wave 15, a generator must produce electrical voltagewhich also has positive-going zero crossings at times 3 and 11 andnegative-going zero crossings at times 7 and 17. It should be understoodthat the present disclosure is directed to synchronizing the voltage ofan auxiliary generator with one of the three phases of the three-phasepower produced by power plants. Thus, the sine wave 15 of FIG. 2 couldrepresent any one of the three phases, i.e., phase-A, phase-B, phase C,produced by a power plant. Each phase being delayed by the other by 120degrees.

Referring now to FIG. 3 a, an apparatus 310 for controlling theinterconnection of an auxiliary generator 330 is illustrated. Theapparatus includes a meter module 52 coupled to the electrical system320 for measuring voltages, V1, V2 and V3 associated with the respectivethree-phase power produced by the power plant 240. The apparatus furtherincludes a synchronization module 54 for controlling the interconnectionof an auxiliary generator to the electrical system 320, as will bedescribed below. It should be understood that elements of thesynchronization module 54 are not shown in FIG. 3 a for clarity.Instead, the elements of the synchronization module 54 are shown in FIG.3 b, and are described further below. The synchronization module 54 isshown coupled to the meter module 52 for receiving a zero-crossing timesignal associated with one of the three-phase voltages (V1, or V2, orV3) from the electrical distribution system.

Meter Module 52

The meter module 52 monitors and determines an amount of electricalpower usage by a consumer as illustrated in FIG. 1. Generally, the metermodule 52 includes sensors 12, a plurality of analog-to-digital (ND)converters 14 and a processing system including a central processingunit (CPU) 18 and/or a digital signal processor (DSP) 16. The sensors 12will sense electrical parameters, e.g., voltage and current, of theincoming lines from an electrical power distribution system. Preferably,the sensors will include current transformers and potentialtransformers, wherein one current transformer and one voltagetransformer will be coupled to each phase of the incoming power lines. Aprimary winding of each transformer will be coupled to the incomingpower lines and a secondary winding of each transformer will output avoltage representative of the sensed voltage and current. The output ofeach transformer will be coupled to the A/D converters 14 configured toconvert the analog output voltage from the transformer to a digitalsignal that can be processed by the CPU 18 or DSP 16.

The CPU 18 is configured for receiving the digital signals from the A/Dconverters 14 to perform the necessary calculations to determine thepower usage and controlling the overall operations of the IED 310. Inanother embodiment, the DSP 16 will receive the digital signals from theA/D converters 14 and perform the necessary calculations to determinethe power usage to free the resources of the CPU 18. It is to beappreciated that in certain embodiments the CPU 18 may perform all thefunctions performed by the CPU 18 and DSP 16, and therefore, in theseembodiments the DSP 16 will not be utilized.

A power supply 20 is also provided for providing power to each componentof the IED 310. Preferably, the power supply 20 is a transformer withits primary windings coupled to the incoming power distribution linesand having an appropriate number of windings to provide a nominalvoltage, e.g., 5 VDC, at its secondary windings. In other embodiments,power is supplied from an independent source to the power supply 20,e.g., from a different electrical circuit, a uninterruptible powersupply (UPS), etc. In another embodiment, the power supply 20 can alsobe a switch mode power supply in which the primary AC signal will beconverted to a form of DC signal and then switched at high frequencysuch as but not limited to 100 Khz and then brought through atransformer which will step the primary voltage down to, for example, 5Volts AC. A rectifier and a regulating circuit would then be used toregulate the voltage and provide a stable DC low voltage output.

The meter module 52 further includes a multimedia user interface forinteracting with a user and for communicating events, alarms andinstructions to the user. The user interface will include a display 30for providing visual indications to the user. The display 30 may includea touch screen, a liquid crystal display (LCD), a plurality of LEDnumber segments, individual light bulbs or any combination of these. Thedisplay 30 may provide the information to the user in the form ofalpha-numeric lines, computer-generated graphics, videos, animations,etc. The user interface will also include a speaker or audible outputmeans 8 for audibly producing instructions, alarms, data, etc. Thespeaker 8 will be coupled to the CPU 18 via a digital-to-analogconverter (D/A) 26 for converting digital audio files stored in a memory19 to analog signals playable by the speaker 8. An exemplary interfaceis disclosed and described in commonly owned co-pending U.S. applicationSer. No. 11/589,381, entitled “POWER METER HAVING AUDIBLE AND VISUALINTERFACE”, which claims priority to U.S. Provisional Patent Appl. No.60/731,006, filed Oct. 28, 2005, the contents of which are herebyincorporated by reference in their entireties.

The meter module 52 will support various file types including but notlimited to Microsoft Windows Media Video files (.wmv), Microsoft PhotoStory files (.asf), Microsoft Windows Media Audio files (.wma), MP3audio files (.mp3), JPEG image files (.jpg, .jpeg, .jpe, .jfif), MPEGmovie files (.mpeg, .mpg, .mpe, .m1v, .mp2v .mpeg2), Microsoft RecordedTV Show files (.dvr-ms), Microsoft Windows Video files (.avi) andMicrosoft Windows Audio files (.wav).

In addition to storing audio and/or video files, memory 22 will storethe sensed and generated data for further processing and for retrievalwhen call upon to be displayed at the meter module 52 or from a remotelocation. The memory 22 includes internal storage memory, e.g., randomaccess memory (RAM), or removable memory such as magnetic storagememory; optical storage memory, e.g., the various known types of CD andDVD media; solid-state storage memory, e.g., a CompactFlash card, aMemory Stick, SmartMedia card, MultiMediaCard (MMC), SD (Secure Digital)memory; or any other memory storage that exists currently or will existin the future. By utilizing removable memory, an IED can be easilyupgraded as needed.

In a further embodiment, the meter module 52 will include acommunication device 28 for enabling communications between the metermodule and other computing devices, e.g., a desktop computer, laptopcomputer, other meter modules, etc. The communication device 28 may be amodem, network interface card (NIC), wireless transceiver, etc. Thecommunication device 28 will perform its functionality by hardwiredand/or wireless connectivity. The hardwire connection may include but isnot limited to hard wire cabling e.g., parallel or serial cables, USBcable, Firewire (1394 connectivity) cables, and the appropriate port.The wireless connection will operate under any of the various knownwireless protocols including but not limited to Bluetooth™interconnectivity, infrared connectivity, radio transmissionconnectivity including computer digital signal broadcasting andreception commonly referred to as Wi-Fi or 802.11.X (where x denotes thetype of transmission), satellite transmission or any other type ofcommunication protocols or systems currently existing or to be developedfor wirelessly transmitting data.

The meter module 52 may communicate to a server or other computingdevice via a communication network. The meter module 52 and server maybe connected to the communications network, e.g., the Internet, by anyknown means, for example, a hardwired or wireless connection, such asdial-up, hardwired, cable, DSL, satellite, cellular, PCS, wirelesstransmission (e.g., 802.11a/b/g), etc. It is to be appreciated that thenetwork may be a local area network (LAN), wide area network (WAN), theInternet or any known network that couples a plurality of computers toenable various modes of communication via network messages. Furthermore,the server will communicate using the various known protocols such asTransmission Control Protocol/Internet Protocol (TCP/IP), File TransferProtocol (FTP), Hypertext Transfer Protocol (HTTP), etc. and secureprotocols such as Internet Protocol Security Protocol (IPSec),Point-to-Point Tunneling Protocol (PPTP), Secure Sockets Layer (SSL)Protocol, etc. The server will further include a storage medium forstoring a database of instructional videos, operating manuals, etc., thedetails of which will be described in detail below.

In an additional embodiment, the meter module 52 will also have thecapability of not only digitizing the waveform, but storing the waveformand transferring that data upstream to a central computer, e.g., aremote server, when an event occurs such as a voltage surge or sag or acurrent short circuit. This data will be triggered on an event, storedto memory, e.g., non-volatile RAM, and additionally transferred to ahost computer within the existing communication infrastructure. Thedigitized waveform will also allow the CPU 18 to compensate otherelectrical parameters such as harmonics, magnitudes, symmetricalcomponents and phasor analysis. Using the harmonics, the IED 10 willalso calculate dangerous heating conditions and can provide harmonictransformer derating based on harmonics found in the current waveform.

In a further embodiment, the meter module 52 will execute an e-mailclient and will send e-mails to the utility or to the customer direct onan occasion that a power quality event occurs. This allows utilitycompanies to dispatch crews to repair the condition. The data generatedby the meters are use to diagnose the cause of the condition. The datais transferred through the infrastructure created by the electricalpower distribution system.

Synchronization Module 54

Referring now to FIG. 3 b, there is shown a detailed block diagram ofthe synchronization module 54 of FIG. 3 a. The synchronization module 54includes a phase-angle computation module 56 for receiving a zerocrossing time of a selected voltage phase and a zero crossing time ofthe auxiliary voltage having a corresponding voltage phase and computesa phase-angle difference as output, a first filter module 58 forfiltering the phase-angle difference output from the phase anglecomputation module 56, a zero-crossing detector 60 for detecting andoutputting the zero crossing time of the auxiliary voltage, a frequencycomputation module 62 for computing a frequency of the auxiliary voltageand a second filter module 64 for filtering the computed frequencyoutput from the frequency computation module 62. The synchronizationmodule 54 is configured to control the interconnection of an auxiliarygenerator 330 to the electrical distribution system 320.

This process is generally described as follows. A more detaileddescription is provided further below with reference to FIG. 4.

Process Overview

Briefly, an overview of a process for controlling the interconnection ofan auxiliary generator 330 to the electrical distribution system 320. isdescribed as follows.

The meter module 52 outputs the zero crossing time, Ta(s) of a voltage,e.g., V1, associated with one phase, e.g., phase-A of the three-phasepower. It is understood that any phase may be selected with the onlyrequirement being that the same phase is selected on the auxiliarygenerator 330. The zero crossing time, Ta(s), of the selected voltagephase is supplied as one input to the phase-angle computation module 56of synchronization module 54.

The phase angle computation module 56 also receives, as a second input,the zero crossing time T-aux of the voltage V1-aux associated with thecorresponding voltage phase, e.g., phase-A, of the auxiliary generator330, as a second input. This second input, T-aux, is output by thezero-crossing detector 60 of synchronization module 54, which receivesV1-aux at its input. V1-aux represents the voltage of phase-A of theauxiliary generator 330. The phase-angle computation module 56 computesa phase angle difference, which is filtered by filtering module 58. Thefiltering module 58 outputs a filtered phase angle difference value,i.e., Phase-Angle_(A-aux).

In a substantially parallel process, the frequency of the auxiliarygenerator 330 is computed by the frequency computation module 62 ofsynchronization module 54. The frequency computation module 62 receivesT-aux as input and computes the frequency of the auxiliary generator330, Freq-aux, as output.

Knowing the frequency of the auxiliary generator 330, Freq-aux(filtered), as computed below in Eq. [2] and knowing the phase angledifference, Phase-Angle-Diff_(A-aux)(filtered), between phase-A of thereference 320 and phase-A, of the auxiliary generator 330, as computedin Eq. [3] below, an operator may synchronize or to control theinterconnection of the auxiliary AC generator 330 with an electricalsystem 320, i.e., utility grid.

Process Flow

With reference now to FIG. 4, there is shown a process 400 forcontrolling the interconnection of an auxiliary generator 330 to theelectrical system 320, in accordance with an embodiment of the presentdisclosure. In operation, the metering module 52 detects the rising edgezero-crossing of the reference line voltage V1 in the current cycle(Step-402). The timer value associated with the rising edgezero-crossing event in the current cycle is captured and stored in amemory of the metering module 52 as variable T-NEW (Step-404). Adetermination is then made regarding whether the timer overflow flag isset (Step-406). The timer overflow flag is set when the timer countingcapacity is reached before the next rising edge zero-crossing interruptoccurs. In the case where the timer overflow flag is set, the overflowcounter is increased by one (Step-408). The timer counting capacity is65536 (or 0x0FFFF in Hex). If an overflow (overrun) occurs, a RAMcounter is increased by one. In later computation, (current timerreading+65536*value of RAM counter) is used as total timer reading.Next, a zero-crossing difference value, T-AUX, is computed between thezero-crossing event in the present cycle, T-NEW, and the timer valueassociated with the zero-crossing event in the previous cycle T-PREVIOUS(Step-410).

T-AUX=T-PREVIOUS−T-NEW  Eq. [1]

The zero-crossing difference value, T-AUX, is accumulated overconsecutive cycles for purposes of smoothing or averaging (Step-412).Next, a determination is made regarding whether an accumulationthreshold for T-AUX has been met. The accumulation threshold may be setto a value, for example, of 500 ms. If the accumulation threshold is notreached, the process returns to step 402 (as described above) to detectthe rising edge zero-crossing of the reference line voltage V1 in thenext waveform cycle (Step-414). Otherwise, the process computes anaveraged or smoothed value for T-AUX, yielding T-AUX-AVERAGED(Step-416). The value T-AUX-AVERAGED is filtered to remove any unwantedhigh-frequency noise, yielding T-AUX-SMOOTHED (Step-418). Then, thefrequency of the auxiliary generator 330 is computed by the frequencycomputation module 62 of the synchronization module 54 as follows(Step-420):

Frequency(aux)=1/[T-AUX-SMOOTHED]  Eq.[2]

Where

T-AUX-SMOOTHED=1/[T-AUX-SMOOTHED(Previous Cycle)−T-AUX-SMOOTHED (CurrentCycle)]

In addition to computing the frequency of the auxiliary generator 330,in accordance with the principles of the invention, it is also necessaryto compute the phase angle difference, Phase-Angle-Diff_(A-aux), betweenphase-A of the reference 320 and phase-A, of the auxiliary generator330. This computation is shown in part 2 of the flowchart of FIG. 4,described as follows. It is first necessary to compute the zero-crossingtime difference T (θ) between the positive zero-crossing time of thereference 320, T-aux SMOOTHED, and T-A, the zero crossing time ofphase-A of the reference 320 for one waveform cycle (Step-424). Thedifference value T (θ) is accumulated over a number of waveform cycles(Step-426). A determination is made regarding whether the differencevalue T (θ) has reached a pre-set accumulation threshold (Step-428). Ifnot, the process returns to step 402 to detect the next incomingzero-crossing event. Otherwise, the process computes an average T (θ)for a number of waveform cycles corresponding to the threshold(Step-430). The value T (θ) is filtered to remove any unwantedhigh-frequency noise, yielding T(θ) SMOOTHED (Step-432). Finally, thephase angle difference value is computed as: (Step-434)

Phase-Angle-Diff_(A-aux) =T(θ)SMOOTHED/[T-AUX SMOOTHED*360]  Eq. [3]

Where T-AUX SMOOTHED is computed as:

T-AUX SMOOTHED=T-AUX SMOOTHED(Cycle x)−T-AUX SMOOTHED(Cycle x+1)  Eq.[4]

Synchronization

Knowing the frequency of the auxiliary generator 330, as computed in Eq.[2] and knowing the phase angle difference, Phase-Angle-Diff_(A-aux),between phase-A of the reference 320 and phase-A, of the auxiliarygenerator 330, as computed in Eq. [3], an operator may synchronize orcontrol the interconnection of the auxiliary AC generator 330 with anelectrical system 320, i.e., utility grid. This process comprises thesteps of adjusting the frequency of the auxiliary generator 330 until itis substantially equal to the frequency of the reference 320 anddetermining that the phase angle difference value,Phase-Angle-Diff_(A-aux), is within a defined tolerance. At that point,the operator may synchronize or control the interconnection of theauxiliary AC generator 330 with the electrical system 320, i.e., utilitygrid. In another embodiment, it is contemplated to provide the metermodule 52 with capabilities for determining when the phase angledifference value, Phase-Angle-Diff_(A-aux), is within a definedtolerance. At that point, the meter module 54 manages thesynchronization or control of the interconnection of the auxiliary ACgenerator 330 with the electrical system 320, i.e., utility grid.

In one embodiment, the apparatus 310 may further include an integrateddisplay for displaying an instantaneous phase, frequency, phase-angledifference values and a visual indication of when the phase angledifference value, Phase-Angle-Diff_(A-aux), is within a definedtolerance, to inform an operator that it is permissible to synchronizeor control the interconnection of the auxiliary AC generator 330 withthe electrical system 320, i.e., utility grid. In this embodiment, theapparatus 310 may be mounted in close proximity to the generator, or ona control panel of the generator, so an operator can receiveconfirmation that the generator is ready to be brought online.

In another embodiment, the apparatus 310 may further include a controlalgorithm for outputting an analog control signal to automaticallycontrol the auxiliary AC generator 330 to synchronize the auxiliary ACgenerator 330 with the electrical system 320, i.e., utility grid at thepoint in time when the phase angle difference value,Phase-Angle-Diff_(A-aux), is within a defined tolerance. In thisembodiment, the apparatus 310 includes a plurality of analog outputswherein at least one analog out is coupled to the generator and providesa frequency adjust signal to adjust the frequency of the generator. Whenthe control algorithm executing in the at least one processor describedabove determines the phase angle of the grid and generator are in synch,e.g., within a predetermined tolerance range, a digital output will senda control signal to the interconnecting contactors 340 to couple thegenerator to the grid. It is to be appreciated that the analog outputsand digital outputs may reside on an external function module coupled tothe apparatus 310 over a standard communication bus, e.g., ModBus, DNP,etc. Alternatively, the analog and digital outputs may terminate on theapparatus 310 as output signal terminals which may be coupled to anexternal device such as a generator controller module. It iscontemplated to output the analog and digital outputs from theapparatus, via a standard communication bus, as described above, to agenerator controller module which is configured to output one or morecontrol signals to the interconnecting contactors 340 to couple thegenerator to the grid.

Referring to FIG. 5, a synchronization system 500 is shown in accordancewith various embodiments of the present disclosure. The synchronizationsystem 500 comprises a plurality of synchronization modules 502corresponding to a plurality of generators 504. According to someembodiments, the synchronization modules 502 may be configured assynchrophasor modules. The synchronization modules 502, or synchrophasormodules, are configured to connect the generators 504 to a power grid506 in synchronization with the voltage phases on the power grid 506.The power grid 506 may comprise any combination of transmission lines,relays, and other components for transmitting electrical power frompower sources to consumers. According to some embodiments, thesynchronization modules 502 may be configured similar to apparatus 310described above and such synchronization modules 502 may includes thestructures and/or components shown in FIGS. 3 a and 3 b.

The synchronization system 500 further includes a communication network508 and a central controller 510. The communication network 508 isconfigured to allow communication among the synchronization modules 502and the central controller 510. The central controller 510 is configuredto distribute control signals to each synchronization module 502 toprovide times when the synchronization modules 502 may connect theirrespective generators 504 online with the power grid 506. The centralcontroller 510 communicates timing signals to the synchronizationmodules 502 to ensure that the voltage phases of the generators 504 aresubstantially synchronized with the voltage phase on the power grid 506.One goal of the central controller 510 is to synchronize the generators504 with the power grid 506 within a predefined tolerance to reducenoise and other inefficiencies.

The synchronization modules 502 may be configured to analyze and recordthe frequency and phase angle at the point where the respectivegenerator 504 will be connected to the power grid 506. In addition, thesynchronization modules 502 may also record an exact timestamprepresenting the exact time the frequency and phase angle were recorded.The timestamp, for example, may be obtained from GPS signals, which maybe accurate within about 10 ns, via an IRIG-B signal generating devicecoupled to the synchronization module 502. This information can becommunicated to the central controller 510 to ensure that the generators504 are synchronized with the voltage signals at each connection pointalong the power grid 506. In some embodiments, the central controller510 may coordinate each generator 504 to be synchronized with each otherat the various points along the power grid 506.

In some embodiments, the communication network 508 may be connecteddirectly to the power grid 506 via a transmission line 512. In thisrespect, communication signals between the central controller 510 andthe synchronization modules 502 may be transmitted along thetransmission lines of the power grid 506. The communication network 508,according to various embodiments, may communicate synchronizationsignals over the power grid 506, Ethernet lines, telephone lines,satellite transmission, cellular transmission, Wifi transmission, WIMAXtransmission, and/or other communication channels. It is to beappreciated that the synchronization modules 502 will include acommunication device appropriate or compatible with a particularcommunication network 508, a communication device that communicates viamultiple modes, e.g., hardwired and wireless or a communication devicethat is adaptable or reprogrammable to various known or to be developedcommunication networks. In various embodiments, the communication deviceof the synchronization modules 502 may be configured similar tocommunication device 28 described above.

The central controller 510 is further configured to determine thenetwork propagation delays based on the propagation of signals betweenthe central controller 510 and the synchronization modules 502 andassociated generators 504. The propagation delay may be a factor ofdistance between the central controller 510 and generators 504, the pathand distance of propagation signals communicated between the centralcontroller 510 and generators, the medium over which the propagationsignals are communicated, and/or other factors that affect may add tothe propagation delay between two devices.

In FIG. 6, a block diagram of the central controller 510 shown in FIG. 5is shown in accordance with one embodiment. As illustrated, the centralcontroller 510 includes a status request module 610, a propagation delaycalculating module 612, a time synchronization module 614, and a controlsignal distribution module 616. In operation, the components of thecentral controller 510 are configured to synchronize the phase of thevoltage signals of the generators 504 with the existing voltage on thepower grid 506.

The status request module 610 is configured to send a signal to each ofthe synchronization modules 502 requesting information about a currentstate of the waveform of the generator 504 corresponding to therespective synchronization module 502. In response, the synchronizationmodules 502 send a snapshot of or information regarding the respectivegenerators' waveforms, including, for example, the frequency of thewaveform and the phase angle with respect to an exact time. Along withthe waveform, the synchronization module 502 also records a timestampwhen the waveform was captured and an exact time when the capturedwaveform is being transmitted back to the central controller 510.

When the central controller 510 receives a waveform from thesynchronization module 502, the network delay calculating module 612 isconfigured to determine an exact time when the waveform is received.This time is compared with the exact time when the waveform wastransmitted by the synchronization module 502 in order to calculate thenetwork delay inherent in the system for transmission over the distance,path, and/or channel from the synchronization modules 502 to the centralcontroller 510. Also, the amount of time from transmission to receptionmay be a factor of the distance between the respective synchronizationmodule 502 and the central controller 510 and may also be a factor ofthe medium along which the signals are transmitted. In order to maintainconsistent time measurements throughout the synchronization system 500,the components of the synchronization system 500 may utilize GPS timesignals for clock synchronization within a tolerance of about 10 ns. Thecomponents may alternatively use other clock or time synchronizationmethods, such as Precise Time Protocol.

Once the time delay is calculated for each synchronization module 502and the beginnings of the periods of the waveforms (or other phase anglemeasurements) are known, the time synchronization module 614 isconfigured to determine the times when the different generators 504 maybe connected. The control signal distribution module 616 is configuredto transmit control signals to each of the synchronization modules 502to control when each generator 504 is to be connected on the power grid506. The control signal distribution module 616 takes the network delayinto account when sending the control signals to the differentsynchronization modules 502.

It is to be understood that the central controller 510 may beimplemented in various forms of hardware, software, firmware, specialpurpose processors, or a combination thereof. In one embodiment, thetechniques of the present disclosure may be implemented in software asan application program tangibly embodied on a program storage device.The application program may be uploaded to, and executed by, the centralcontroller 510 comprising any suitable architecture such as a personalcomputer, a workstation, server, etc. In one embodiment, the centralcontroller 510 is implemented on a computer platform having hardwaresuch as one or more central processing units (CPU), a random accessmemory (RAM), a read only memory (ROM) and input/output (I/O)interface(s) such as a keyboard, cursor control device (e.g., a mouse orjoystick) and display device. A system bus couples the variouscomponents and may be any of several types of bus structures including amemory bus or memory controller, a peripheral bus, and a local bus usingany of a variety of bus architectures. The computer platform alsoincludes an operating system and micro instruction code. The variousprocesses and functions described herein may either be part of the microinstruction code or part of the application program (or a combinationthereof) which is executed via the operating system.

In addition, various other peripheral devices may be connected to thecomputer platform of the central controller 510 by various interfacesand bus structures, such a parallel port, serial port or universalserial bus (USB). One such peripheral device may include acommunications device, e.g., a modem, satellite relay, wirelessconnection, etc., for enabling communications from the centralcontroller 510 to various synchronization modules 502. Other peripheraldevices may include additional storage devices, a printer and a scanner.

It is to be further appreciated that the central controller 510 may beincorporated into one of the synchronization modules 502. In thisembodiment, the central controller 510 may be embodied on a printedcircuit board, e.g., as a plug-n-play card, which is disposed within ahousing of the synchronization module 502.

The present disclosure provides a system and method for measuring andanalyzing synchronized real-time data of multiple remote measurementpoints on an electrical power distribution grid. Although variousembodiments were described above in relation to adding multiplegenerators to a grid, the techniques of the present disclosure may beemployed to measure or assess the state of the grid and manage powerquality. For example, the techniques of the present disclosure may beused for power system automation; load shedding and other load controlmethodologies; disturbance recording and analysis; prevention of poweroutages; fault detection; wide area control of local distribution grids,regional transmission networks and the like.

While the disclosure has been shown and described with reference tocertain preferred embodiments thereof, it will be understood by thoseskilled in the art that various changes in form and detail may be madetherein without departing from the spirit and scope of the disclosure.

Furthermore, although the foregoing text sets forth a detaileddescription of numerous embodiments, it should be understood that thelegal scope of the invention is defined by the words of the claims setforth at the end of this disclosure. The detailed description is to beconstrued as exemplary only and does not describe every possibleembodiment, as describing every possible embodiment would beimpractical, if not impossible. One could implement numerous alternateembodiments, using either current technology or technology developedafter the filing date of this patent, which would still fall within thescope of the claims.

It should also be understood that, unless a term is expressly defined inthis patent using the sentence “As used herein, the term ‘______’ ishereby defined to mean . . . ” or a similar sentence, there is no intentto limit the meaning of that term, either expressly or by implication,beyond its plain or ordinary meaning, and such term should not beinterpreted to be limited in scope based on any statement made in anysection of this patent (other than in the claims). To the extent thatany term recited in the claims at the end of this patent is referred toin this patent in a manner consistent with a single meaning, that isdone for sake of clarity only so as to not confuse the reader, and it isnot intended that such claim term be limited, by implication orotherwise, to that single meaning. Finally, unless a claim element isdefined by reciting the word “means” and a function without the recitalof any structure, it is not intended that the scope of any claim elementbe interpreted based on the application of 35 U.S.C. §112, sixthparagraph.

What is claimed is:
 1. A system comprising: a plurality of powergenerators configured to be connected to transmission lines of anexisting power grid; a plurality of synchronization modules, eachsynchronization module corresponding to one of the plurality of powergenerators and configured to output a control signal to adjust afrequency of the respective power generator to correspond with thefrequency of the existing power grid; and a central controller incommunication with the plurality of synchronization modules, the centralcontroller configured to determine a propagation delay with respect toeach synchronization module, the propagation delay being a measure oftime for a signal to propagate from the respective synchronizationmodule to the central controller; wherein the central controller isfurther configured to send a control signal to each synchronizationmodule to control when each synchronization module connects therespective power generator to the existing power grid.
 2. The system ofclaim 1, further comprising a communication network, wherein the centralcontroller communicates with the plurality of synchronization modulesvia the communication network.
 3. The system of claim 2, wherein thecommunication network is configured to communicate with the plurality ofsynchronization modules via the power grid.
 4. The system of claim 1,wherein the central controller is configured to determine thepropagation delay using time signals synchronized using GPS signals. 5.The system of claim 1, wherein the central controller is furtherconfigured to transmit a request to obtain the status of each of thesynchronization modules.
 6. The system of claim 1, wherein eachsynchronization module is associated with a meter module configured tosense electrical parameters of an electrical power distribution systemassociated with the power grid.
 7. The system of claim 6, wherein eachsynchronization module is further configured to compute a frequency of avoltage waveform of the respective power generator using zero-crossingtimes of the voltage waveform.
 8. The system of claim 6, wherein eachsynchronization module is further configured to compute a phase angledifference between a voltage waveform of the respective power generatorand the electrical power distribution system.
 9. The system of claim 1,wherein the central controller is incorporated in one of thesynchronization modules.
 10. A method comprising: associating aplurality of synchronization modules with a plurality of respectivepower generators; outputting a control signal from each of thesynchronization modules to adjust a frequency of the respective powergenerator to correspond with the frequency of an existing power grid;determining a propagation delay with respect to each synchronizationmodule, the propagation delay being a measure of time for a signal topropagate from the respective synchronization module to a centralcontroller; and sending a control signal from the central controller toeach synchronization module to control when each synchronization moduleconnects the respective power generator to the existing power grid. 11.The method of claim 10, wherein sending the control signal furthercomprises communicating through a communication network.
 12. The methodof claim 11, wherein sending the control signal further comprisescommunicating with the plurality of synchronization modules via thepower grid.
 13. The method of claim 10, further comprising determiningthe propagation delay using time signals synchronized using GPS signals.14. The method of claim 10, further comprising transmitting a request toobtain the status of each of the synchronization modules.
 15. The methodof claim 10, further comprising sensing electrical parameters of anelectrical power distribution system associated with the power grid. 16.The method of claim 15, further comprising computing a frequency of avoltage waveform of the respective power generator using zero-crossingtimes of the voltage waveform.
 17. The method of claim 15, furthercomprising computing a phase angle difference between a voltage waveformof the respective power generator and the electrical power distributionsystem.
 18. The method of claim 10, wherein sending the control signalto each of the synchronization modules further comprises staggering thecontrol signals to prevent two power generators from being connected tothe power grid at the same time.